um 1610, testimony & exhibits, 8/7/2015

August 7, 2015

Via Electronic Filing OREGON PUBLIC UTILITY COMMISSION ATTENTION: FILING CENTER PO BOX 1088 SALEM OR 97308-1088 RE: Docket No. UM 1610 PH II – In the Matter of PUBLIC UTILITY COMMISSION OF OREGON Staff Investigation Into Qualifying Facility Contracting and Pricing. Enclosed for electronic filing is Public Utility Commission Staff’s Reply Testimony.

/s/ Kay Barnes

Kay Barnes Filing on Behalf of Public Utility Commission Staff (503) 378-5763 Email: [email protected]

Public Utility Commission 201 High Street SE, Suite 100

Salem, OR 97301-3612

Mailing Address: PO Box 1088

Salem, OR 97308-1088

Consumer Services 1-800-522-2404

Local: (503) 378-6600

Administrative Services (503) 373-7394

Oregon Kate Brown, Governor

CASE: UM 1610 PH II WITNESS: BRITTANY ANDRUS

PUBLIC UTILITY COMMISSION OF

OREGON

STAFF EXHIBIT 700

Reply Testimony

August 7, 2015

Docket UM 1610 PH II Staff/700 Andrus/1

UM 1610 Ph II Reply Testimony

Q. Please state your name, occupation, and business address. 1

A. My name is Brittany Andrus. My business address is 201 High Street SE Suite 2

100, Salem, Oregon 97301-3612. 3

Q. Please describe your educational background and work experience. 4

A. My Witness Qualification Statement is found in Exhibit Staff/301 and Staff/501. 5

Q. What is the purpose of your testimony and how is it organized? 6

A. I have previously filed opening and response testimony in Phase II of this 7

docket addressing nine issues relating to the Commission’s implementation of 8

the Public Utility Regulatory Policy Act (PURPA). In this testimony, I reply to 9

some of the response testimony offered by other parties. 10

Issue No. 1: Who owns the Green Tags during the last five years of a 11

20-year fixed price PPA during which prices paid to the qualifying facility 12

(QF) are at market? 13

Q. Does any party offer a persuasive reason as to why QFs should cede 14

Renewable Energy Credits (RECs) to the utilities during a deficiency 15

period in the last five years of a standard contract when the QF is 16

receiving sufficiency-period prices? 17

A. No. PacifiCorp opposes testimony by Staff and other parties on this issue, 18

asserting these parties “equat[e] being paid market-based avoided costs during 19

the resource deficiency period to the Company returning to a resource 20

sufficiency period and therefore the RECs should be retained by the QF.”1 21

PacifiCorp’s characterization of Staff’s argument is incorrect. 22

1 PAC/1300, Griswold/5.



Staff does not believe that the QFs’ receipt of market-based prices in the 1

last five years of a standard contract signifies the utility is resource sufficient. 2

The point of Staff’s testimony is that QFs are not compensated for RECs when 3

they receive market-based prices in the last five years of a standard contract. 4

If QFs are not compensated for the RECs, they should not be required to 5

transfer ownership of RECs to utilities, even if the utilities are resource 6

deficient. 7

Issue No. 2: Should avoided transmission costs for non-renewable and 8

renewable proxy resources be included in the calculation of avoided cost 9

prices? 10

Q. Is Staff persuaded by PacifiCorp’s arguments that the Company can 11

never avoid transmission costs in connection with a proxy resource 12

that is on system? 13

A. No. With respect to third-party transmission costs, PacifiCorp testifies: 14

Avoided costs should not include assumed reductions in 15 transmission service costs or third-party wheeling expenses due to 16 the addition of a QF on PacifiCorp’s system. Planned resource 17 acquisitions included in the Company’s IRP are sited within 18 PacifiCorp’s service territory and do not require third-party 19 transmission to reach the Company’s system.2 20

PacifiCorp’s assertion that planned resource acquisitions “are sited within 21

PacifiCorp’s service territory and do not require third-party transmission to 22

reach the Company’s system” is inconsistent with its assertion that certain QFs 23

sited within its service territory will cause it to incur third-party transmission 24

2 PAC/1100, Dickman/5.



costs.3 While PacifiCorp acknowledges that the Community Renewable 1

Energy Association (CREA) points out this inconsistency in CREA’s response 2

testimony, PacifiCorp does not satisfactorily explain why a QF in a load pocket 3

on PacifiCorp’s system may need third-party transmission but a proxy resource 4

in the same circumstance will not.4 5

PacifiCorp also does not satisfactorily explain why there will never be 6

avoided costs for upgraded or new transmission facilities associated with an 7

avoided proxy resource. Accordingly, Staff recommends that the Commission 8

clarify that avoided transmission costs will be included in the calculation of 9

avoided cost prices whether the proxy resource is off-system or on-system, 10

provided that it is shown that such costs would be avoided. 11

Issue No. 3: Should the Commission revise the methodology approved in 12

Order No. 14-058 for determining the capacity contribution adder for solar 13

QFs selecting standard renewable avoided cost prices? If so, how? 14

And 15 Issue No. 4: Should the capacity contribution calculation for standard 16

non-renewable avoided cost prices be modified to mirror any change to 17

the solar capacity contribution calculation used to calculate the standard 18

renewable avoided cost price? 19

Q. There have been several rounds of testimony on the calculation of the 20

capacity contribution adjustment for Standard Renewable Avoided Cost 21

Prices. Does Staff have anything to add to its previous testimony? 22

3 PAC/ 1300, Griswold/11-13.

4 PAC/1100, Griswold/12.



A. PacifiCorp and Idaho Power continue to misunderstand Staff’s proposed 1

change to the capacity contribution adjustment. PacifiCorp testifies that Staff’s 2

position “boils down to a proposal that the solar capacity adder should be 3

determined as a fixed dollar amount equal to the cost of an avoided thermal 4

resource and that each QF should receive the entire amount regardless of its 5

actual output during on peak hours.”5 Idaho Power testifies that “[t]he parties 6

discuss an outdated concept that a QF is entitled to a fixed amount capacity 7

payment, regardless of when it generates.”6 8

Q. Does Staff recommend that QFs receive a fixed amount no matter when or 9

how much they generate? 10

A. No. QFs would continue to receive capacity payments only for the on-peak 11

hours in which they generate. The value of the QF’s contribution to the utility’s 12

peak would be calculated as an annual dollar value, which would be converted 13

to a rate to be paid only for the on-peak megawatt-hours the QF actually 14

delivers. QFs would not be “entitled” to a fixed or target amount. 15

Issue No. 5: What is the appropriate forum to resolve litigated issues 16

and assumptions? 17

Q. What is Staff’s position on this issue? 18

A. Staff recommends that the Commission maintain the status quo, but confirm 19

that the resource sufficiency/deficiency demarcation in the utility’s Integrated 20

Resource Plan (IRP) is subject to challenge in the review of the utility’s avoided 21

5 PAC/1100, Dickman/7.

6 Idaho Power/1000, Youngblood/6.



cost filings like any input into avoided cost prices taken from the IRP, and also, 1

require the utilities to comply with minimum filing requirements (MFRs). 2

Q. What is the status quo? 3

A. Each utility is required to file updated avoided cost prices within 30 days of 4

acknowledgment of the utility’s IRP. “Avoided cost filings are subject to 5

suspension and the same investigatory process that any tariff filing may 6

undergo.”7 7

Q. What is the issue regarding the MFRs? 8

A. Staff recommends that the Commission require the utilities to comply with 9

MFRs so that utilities will very clearly identify the inputs used to calculate the 10

avoided cost prices.8 The utilities object to Staff’s proposal because it will 11

mean more work for the utilities and because the inputs are already included in 12

the IRP.9 13

Q. What is Staff’s response to these assertions? 14

A. The utilities are correct, that Staff’s proposed MFRs will mean additional work 15

for them. However, the burden is not an unreasonable one. The utilities are 16

already required to use the inputs to prepare their avoided cost filings. Staff’s 17

proposed MFRs would require the utilities to do a modest amount of additional 18

work to provide Staff and stakeholders information as to how the utilities 19

calculated the avoided cost prices. 20

7 Order No. 05-584 at 36-37. See also OAR 860-029-0080(6) (“Any standard rates filed under

OAR 860-029-0040 shall be subject to suspension and modification by the Commission.”). 8 See Staff Exhibit 530 for list of MFRs.

9 PAC/1200, Drennan/12-13.



Second, the fact that the information is already in the IRP misses the point 1

of Staff’s recommendation. Currently, Staff and parties often have to search 2

the IRPs to find the inputs that match those used in the avoided cost prices to 3

verify their accuracy. This can be a time-consuming task. Having a utility point 4

Staff and parties to where in the utility’s IRP they may find the inputs used to 5

determine avoided cost prices will expedite any process needed to review the 6

utilities’ avoided cost filings and likely reduce the need for discovery. 7

Q. Why is it necessary to confirm that resource sufficiency/deficiency 8

demarcation is subject to challenge in the review of utilities’ avoided 9

cost price filings? 10

A. In Order No. 10-488, the Commission stated that the IRP process is the 11

appropriate venue to determine resource sufficiency and deficiency.10 Some 12

parties assert that the determination of resource sufficiency/deficiency taken 13

from the IRP is not subject to challenge in connection with review of the 14

utilities’ avoided cost filings. 15

Q. Should the resource sufficiency/deficiency demarcation taken from the 16

IRP be treated as any other avoided cost price input? 17

A. Yes. Staff does not think that the Commission’s order specifying that the 18

resource deficiency/sufficiency period is determined in the IRP process and is 19

based on when the utility plans to acquire its next major or renewable resource 20

meant that this input is not subject to challenge like any other input into 21

avoided cost prices. In fact, treating the resource sufficiency/deficiency 22

10

Order No. 10-488 at 8.



demarcation like any other input can be beneficial to the utility. On 1

April 24, 2015, Idaho Power asked the Commission for approval to change its 2

avoided cost prices to reflect a changed resource deficiency period start date. 3

If the resource sufficiency/deficiency demarcation is an input that can only be 4

changed in the IRP, Idaho Power’s application to update its avoided cost prices 5

for a different resource deficiency period start date must fail. 6

Q. Will allowing parties to challenge the resource sufficiency/deficiency 7

demarcation in the process following an avoided cost filing encourage 8

litigation? 9

A. Staff does not think so. As noted above, Staff recommends maintaining the 10

status quo, with two caveats: 1) the utilities will file MFRs with post-IRP 11

avoided cost updates; and 2) the resource sufficiency/deficiency demarcation 12

will be treated like any other input in the avoided cost compliance filings. The 13

status quo has been in effect since at least 2005. The Commission can look to 14

history to determine whether allowing stakeholders to challenge avoided cost 15

price inputs taken from the IRP leads inexorably to litigation. It does not. 16

Q. What is your response to Idaho Power’s assertion that the “compliance 17

process” after the utility makes an avoided cost filing should be 18

limited to verifying that the utility used the correct inputs from the 19

IRP?11 20

A. Staff agrees with Idaho Power to the extent it argues that the avoided cost 21

price review process is not the appropriate venue to resolve policy issues. 22

11

Idaho Power/100, Allphin/4-5.



For example, although the resource sufficiency/deficiency demarcation should 1

be subject to challenge, the method the Commission uses to determine the 2

demarcation—the acquisition date of next major resource—should not. 3

Staff does not agree with Idaho Power, however, that the avoided cost 4

price review process is limited to verifying that the utilities have used the inputs 5

they have been directed to use. Staff recognizes that there may be few well-6

founded challenges to inputs taken from the IRP. This is because the utility’s 7

avoided cost prices are based on the utility’s avoided costs, and the utility’s 8

resource acquisition plan is the best source of information for what costs the 9

utility may avoid. However, there may be circumstances in which it is clear the 10

utility’s actions will not match the utility’s plan or in which the utility’s reliance on 11

a particular input from the IRP is so unreasonable that correction is necessary. 12

A review process to capture these circumstances is necessary. 13

Issue No. 6: Do market prices used during the Resource Sufficiency 14

Period sufficiently compensate for capacity? 15

Q. Has any party offered a persuasive reason to change the 16

Commission’s policies regarding avoided cost prices during the 17

utilities’ sufficiency periods? 18

A. No. Staff finds the QFs’ testimony on this issue to be confusing because they 19

offer different arguments as to why market-based prices are not sufficient to 20

compensate QFs for capacity during sufficiency periods and offer a joint 21

proposal for how to compensate QFs for capacity during sufficiency periods 22



that is difficult to reconcile with the Commission’s current avoided cost price 1

framework. 2

The Renewable Energy Coalition (REC) testifies that market-based prices 3

do not adequately compensate during sufficiency periods because utilities are 4

actually making significant short-term market purchases and investing in 5

thermal resources.12 6

CREA testifies “the differentiation of on-peak and off-peak prices found in 7

the wholesale power market does not in any meaningful analytical way reflect 8

the value of capacity, as that term has been traditionally used in the utility 9

industry. Rather, it is a reflection of simply supply and demand.”13 10

The Joint QF Parties assert that market-based prices do not adequately 11

compensate QFs for capacity during sufficiency periods given the current risk 12

associated with coal resources and PacifiCorp’s investments to retain its coal 13

resources.14 14

Q. What remedy do the QFs recommend to resolve these alleged flaws in 15

the Commission’s methodology? 16

A. CREA and the Joint QF Parties recommend the Commission implement an 17

“interim capacity pricing mechanism” based on the net present value of 18

PacifiCorp’s planned investment in coal resources during the sufficiency period 19

to attribute some value to the capacity of renewable and zero-emission 20

12

Coalition/400, Lowe/18-19. 13

CREA/600, Skeahan/11-12. 14

Joint QF Parties/100, Higgins/5-6.



resources during PacifiCorp’s sufficiency period until the uncertainty regarding 1

implementation of 111(d) is resolved.15 2

Q. What concerns does Staff have with the QF testimony on this subject 3

and the Joint QF Proposal? 4

A. The flaw in the QFs’ arguments is that they do not address or reconcile to 5

Commission’s current policies on market-based prices and demarcation of 6

resource deficiency periods when QFs are compensated for their capacity 7

based on the fixed costs of the next renewable resource. For example, CREA 8

disagrees with the Commission’s conclusion that on-peak forward market 9

prices include a capacity component.16 But, CREA’s recommended solution 10

does not address this alleged flaw in the Commission’s avoided cost 11

methodology. Instead, the recommended solution is an ad hoc mechanism to 12

capture the value of avoided risk related to coal regulations. Similarly, REC’s 13

argument that market-based prices do not adequately compensate QFs for 14

avoided capacity when utilities are making significant market purchases during 15

the sufficiency period and investing in existing thermal resources17 is 16

essentially an attack on the Commission’s policy that acquisition of a major 17

resource (at least five years in duration and 100 MW) signals the start of a 18

deficiency period. But, rather than proposing to modify how the Commission 19

determines when a deficiency period starts, REC recommends that the 20

Commission adopt the interim capacity mechanism. 21

15

Joint QF Parties/100, Higgins/12-14. 16

CREA/600, Skeahan/12. 17

Coalition/100, Lowe/18-19, Coalition/500, Lowe/7.



Q. Does Staff have concerns with the interim capacity mechanism? 1

A. Yes. As explained in Staff’s response testimony, Staff does not think the 2

Commission has authority to include an adder to avoided costs that is not 3

based on real costs the utility will avoid.18 4

Issue No. 7: What is the most appropriate methodology for calculating 5

non-standard avoided cost prices? Should the methodology be the same 6

for all three electric utilities operating in Oregon? 7

Q. The Oregon Department of Energy (ODOE) recommends that if the 8

Commission allows utilities to use a model-based approach to 9

calculate non-standard avoided cost prices, the Commission should 10

require that wholesale prices should serve as the floor for avoided cost 11

prices. Does Staff agree with this recommendation? 12

A. Yes. As ODOE notes,19 utilities used to utilize decremental generating costs to 13

determine standard avoided cost prices during sufficiency periods.20 In 14

Order No. 05-584, the Commission decided that such prices did not sufficiently 15

compensate QFs for avoided capacity and ordered utilities to value “avoided 16

costs when a utility is in a resource sufficient position at monthly on- and off-17

peak forward market prices as of the utility’s avoided cost filing.”21 Although 18

that order applied to the calculation of standard avoided cost prices, the same 19

18

Staff/600, Andrus/19. 19

ODOE/900, Carver/10 (“Previously, decremental generating costs were used during periods of sufficiency.”). 20

See Order No. 05-584 at 27 (“When in a period of resource sufficiency, PGE and PacifiCorp have historically calculated avoided costs based only on the variable costs of operating existing generating resources.”). 21

Order No. 05-584 at 28.



reasoning supports the use of wholesale prices as a floor in the calculation of 1

non-standard rates. 2

Issue No. 8: When is there a legally enforceable obligation? 3

Q. Gardner Solar recommends that if the Commission adopts Staff’s 4

position regarding when a QF can show a legally enforceable 5

obligation (LEO), the Commission should adopt a mechanism by which 6

the QF can make this showing.22 Does Staff agree that such a 7

mechanism is necessary? 8

A. It is not necessary. Staff suspects that Gardner Solar is not aware that the 9

Commission approved the use of a dispute resolution process for standard 10

contract negotiations in Order No. 15-130. Staff believes the dispute resolution 11

mechanism should be sufficient to allow a QF to make the necessary showing 12

without going through the process of filing a formal complaint. 13

ISSUE NO. 9: HOW SHOULD THIRD-PARTY TRANSMISSION COSTS TO 14

MOVE QF OUTPUT IN A LOAD POCKET BE CALCULATED AND 15

ACCOUNTED FOR IN THE STANDARD CONTRACT? Q. What is Staff’s 16

position regarding PacifiCorp’s proposal to allocate third-party 17

transmission costs to move QF output from a load pocket? 18

A. PacifiCorp proposes that when a QF is located in what PacifiCorp determines 19

to be a load pocket, PacifiCorp will secure enough firm long-term transmission 20

to export excess generation from the load pocket for the term of the contract 21

and include the costs of this transmission in an addendum to the standard 22

22

Gardner Solar/200, Benga/3.



contract.23 Staff is not prepared to support this expensive and inflexible 1

method for allocating costs to the QF in every load pocket situation under the 2

standard contract. 3

Q. Please explain the factors Staff evaluated in arriving at this position? 4

A. Order 14-058 requires the utilities to assign to the QF any third-party 5

transmission costs incurred to move QF output from the point of delivery to 6

load. Meeting the objective of assigning costs to a 20-year contract while 7

reasonably accounting for future transmission rate changes, load pattern 8

changes, and potential incremental generation, combined with multiple 9

transmission products, is inherently complex, 10

Q. What does Staff recommend? 11

A. Given the difficulty of analysis, Staff believes that all the parties need 12

sufficient time to investigate PacifiCorp’s proposed transmission cost 13

allocation methodology and to evaluate the feasibility of other options 14

proposed in this case. Staff recommends the Commission defer this issue to 15

Phase III of this investigation for further review. 16

Q. Does this conclude your testimony? 17

A. Yes. 18

23

PAC/1300, Griswold/18.

um 1610, testimony & exhibits, 8/7/2015

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